Large quantities of extractable hydrocarbons exist in subsurface shale formations and other low-permeability strata, such as the Monterey Formation in the United States and the Bakken Formation in the United States and Canada. However, extraction of hydrocarbons from certain low-permeability strata at commercially useful rates has proven to be a challenge from technical, economic and environmental perspectives. One approach for extracting hydrocarbons from shale and other low permeability rocks has been to induce large scale massive fractures in the formation through the use of elevated hydraulic pressure acting on a fluid in contact with the rock through a wellbore. However, this is often accompanied by serious environmental consequences such as a large surface “footprint” for the necessary supplies and equipment, as well as relatively high costs. As well, concerns have been expressed regarding the potential environmental impact from the use of synthetic additives in hydraulic fracturing solutions. These financial and other factors have resulted in difficulties in commercial hydrocarbon extraction from shale oil beds and other low permeability strata.
In general, conventional hydraulic fracturing methods generate new fractures or networks of fractures in the rock on a massive scale, and do not take significant advantage of the pre-existing networks of naturally occurring fractures and incipient fractures that typically exist in shale formations.
A typical shale formation or other low-permeability reservoir rock, as depicted in FIG. 1, comprises the matrix rock intersected by a network of low conductivity native or natural fractures 10 and fully closed incipient fractures 12 extending throughout the formation. Such in situ natural fractures tend be on the micro-scale. FIG. 1 is a two-dimensional depiction of a three-dimensional fracture network in a rock mass with a low-permeability matrix. It is understood that in reality there are many three-dimensional effects, and that the rock mass is acted upon by three orthogonally oriented principal compressive stresses, but in FIG. 1 only the maximum and the minimum far-field compressive stresses—oHMAX 14 and ohmin 16 respectively, acting in the cross-section are represented. The natural fractures 10 and planes of weakness typically exist in a highly networked configuration with intersections between the fractures, and usually but not always with certain directions having more fractures than others, depending on past geological processes.
In their natural state, some of the fractures may be open to permit flow, but in most cases require stimulation. The majority of fractures are almost fully closed or are not yet fully formed fractures. The relative stiffness and the geological history of the rock engenders the natural formation of the network of actual and incipient fractures. The natural fractures 10 are mostly closed as a result of the elevated compressive stresses acting on the rock as depicted in FIG. 1, and because the rock mass has not been subjected to any bending or other deformation. In their closed state, fractures provide little in the way of a pathway for oil, gas or water to flow towards a production well. When closed, fractures do not serve a particularly useful role in the extraction of hydrocarbons or thermal energy.
In prior art fracture processes, sometimes referred to as “high rate fracturing” or “frac-n-pack”, a fracture fluid which usually comprises a granular proppant and a carrying fluid, often of high viscosity, is injected through wellbore 18 into the injection well 19 at a high rate, for example in the range of 15-20 or more barrels per minute (bpm), often 25-40 bpm. As well, injection pressures in the range of 15,000 psi may be used to generate a highly fractured network composed essentially of artificially induced fractures. As depicted in FIGS. 2 and 3, this process tends to generate relatively large, extensive, fractures that propagate outwardly from the wellbore 18 of the injection well 19, which are essentially all propped with a proppant in order to provide flow paths for extraction of a resource. These ‘conventional fractures’ are typically very large fractures that extend into the far-field area of the formation away from the wellbore. In a typical sandstone reservoir, the process creates a dominantly bi-directional fracture orientation with the major induced fractures oriented at ˜90° to the smallest stress in the earth, depicted as the primary fractures 20 FIG. 2. Secondary fractures 22 may form to a limited extent, as seen in FIG. 2, depending on the in situ stress state. The fluid generating the fracture is gradually dissipated across the walls of the fracture planes in the direction of the maximum pressure gradient as fracture fluid down-gradient leak-off 24 (FIG. 2). Overall, each of these fracturing events are relatively isolated and limited in terms of the overall rock volume being accessed, away from the fracture plane, during the fracturing injection process. Furthermore, conventional processes tend to extract the oil or other resource by draining the resource initially from the region remote from the well followed by progressively draining the formation closer to the well with more induced fracturing. Most conventional processes may fracture a relatively large area but are limited in the overall drainage volume from which the resource is drained following the induced fracturing step.
In prior art, high proppant concentration methods employing viscous fluids (fracturing fluids) with high contents of granular proppant (FIG. 3), said proppant also tends to be forced between the wellbore 18 and the rock 21 under a high hydraulic fracture injection rate, to create a zone 23 of proppant fully or substantially fully surrounding the injection well 19. This provides good contact (hydraulic communication) with the induced near-well fractures 8 and connecting with the primary 20 fractures emanating from the region of the wellbore 18 (FIG. 2). The large size of the hydraulic fracture wings 28 interacts with the natural stress fields 30 (FIG. 2) so that it is necessary to inject at a pressure substantially above the minimum far-field compressive stresses σhmin 14 (FIGS. 1 and 2). In the prior art it has been described as necessary to co-inject a relatively large amount of proppant suspended within the viscous fracturing fluid to maintain the induced fractures 8 and 20 in an open state and in a state of high fluid conductivity once the high injection pressures are ceased. The fracture patterns which result from at least some prior art processes are characterized by a relatively limited bi-directional fracture orientation, with relatively poor volumetric fracture sweep because of a limited number of fracture arms/wings 28. The efficiency of interaction between the created fractures and the natural fracture flow system within the formation is believed to be low in such cases, and the lowest efficiency is associated with hydraulically induced fractures 20 of thin aperture and consisting only of two laterally opposed wings with no secondary fractures.
In certain prior art fracturing processes, liquids are deliberately made more viscous through the use of gels, polymers and other additives so that the proppants can be carried far into the fractures, both vertically and horizontally. Furthermore, in said prior art fracturing, extremely fine-grained particulate material may be added to the viscous carrier fluid to further block the porosity and reduce the rate of fluid leak off to the formation so that the fracture fluids can carry the proppant farther into the induced fractures 20, 22. Prior art fracturing is typically designed as a continuous process with no interruptions in injection and no pressure decay or pressure build-up tests i.e., no PFOT, SRT are carried out within the process to evaluate the stimulation effects upon the natural fracture network to or the flow nature of the generated interconnected extensive fracture network. Prior art fracturing processes typically do not shut down, and in some realizations, increase the proppant concentration in a deliberate process intended to create a large, single, propped fracture. In the prior art it is clear that the primary mode and intent of creating high fluid conductivity is the creation of these large isolated hydraulic fracture events (as described herein) with complex fracture fluid(s) and proppant placements, that propagate far into the formation with no significant interaction with the in situ natural fracturing systems that are present in the formation.
Methods of fracture enhancement that are currently used do not necessarily enhance shear dilation of fractures within the rock, therefore they may be sub-optimum in terms of the potential volume of rock mass contacted, which, as indicated above, is a first-order control on the success of the operation.
A conventional fracture operation typically uses a highly viscous fluid and a high injection rate. In practice, the strong opening of the hydraulic fracture near the wellbore increases the stresses across the natural fractures on either side of the induced fracture, and this tends to reduce the tendency to slip (since the frictional strength is increasing across the fracture surfaces). However, if the high pore pressures penetrate this zone, the pressures can overcome the high stresses, reducing the frictional resistance and allowing slip to take place. If the fracturing fluid is viscous, the high pressures cannot penetrate the rock mass on either side of the induced hydraulic fracture, therefore the rock mass remains “locked” as the result of the high frictional forces, and the opening mode for a single fracture is dominant—i.e. there is little or no shear displacement/dilation in the adjacent rock mass. No matter how much proppant may be placed in such a fracture, the rock mass permeability enhancement may not propagate very far beyond the induced fracture region because the pore pressure migration is impeded by the fracture fluid viscosity, therefore the stimulated volume is limited. Furthermore, a coarse-grained single-sized proppant, although it may be carried far into the single fracture, has almost no chance of entering into the secondary fractures that may be opened and connected with the induced hydraulic fracture because the aperture of these secondary fractures is substantially less than the aperture of the primary fracture. When fracturing ceases, these secondary fractures, which may have experienced very little shear displacement, are only weakly flow-enhanced and have largely closed; and therefore provide no benefit to subsequent resource extraction. The way to trigger shear (and thus conductivity enhancement) is to increase the pore pressure in the natural fracture system in as large a volume as possible, so that as many natural fractures as possible can experience shear and dilation.
In a prior art “slickwater” fracture process, one or more of a group of appropriate polymers is added to the water to reduce its frictional resistance as it moves through small aperture fractures. In typical slickwater fracturing, extremely high injection rates are employed and the goal is to develop fracture length by carrying the fracturing fluid far from the injection point to obtain enhancement in apertures from the shear dilation effect. However, the extremely high rates used, often injecting at the very top capacity of a number of pumping trucks, while it may cause impressive length growth, also results in a very large net pressure increase on the walls of the fracture (net pressure is the difference between the pressure in the fluid in the fracture and the minimum compressive stress seeking to close the fracture). Because rates are so high, this value is large, and this tends to significantly increase the locking force, which keeps the natural fractures on both sides of the induced fracture from opening easily as the result of the stress increase, which increases the frictional resistance to slip (as described above). Because the fractures are not opened so much, there is impairment in terms of the injection rate at which the induced pressures can interact with the natural fractures and allow them to slip.